Generation of power from geothermal heat sources is well established. Geothermal heat sources have been the subject of intensified interest as a resource for both electrical power and for direct use in heating applications during recent energy shortages. Geothermal wells in different geographical areas provide steam and water which vary over a wide range as to pressure, temperature, relative amounts of water and steam, mineral content, and composition and quantity of noncondensable gases. Effluents from power plants fueled by geothermal heat sources typically include a variety of contaminants, such as CO.sub.2, H.sub.2 S, NH.sub.3, and CH.sub.4. Except for H.sub.2 S, the natural contaminant levels of these gases may be released to the atmosphere in the effluent. However, regulatory limits on the amount of H.sub.2 S requires treatment of the effluent.
Hydrogen sulfide is a flammable, poisonous gas, and release of hydrogen sulfide to the atmosphere may be dangerous to human, animal and plant life. The presence of hydrogen sulfide in the atmosphere moreover produces a noxious, unpleasant odor. The extent to which contaminants such as hydrogen sulfide are present in geothermal power plant effluents varies significantly as to both type and quantity in the known geothermal sources around the world, but substantially complete removal and safe disposal of hydrogen sulfide from geothermal power plant effluents is a universal problem associated with generation of power from geothermal heat sources.
The exhaust flow from a geothermal power plant steam turbine is typically conveyed to a main condenser for separation of aqueous condensate and dissolved materials from the noncondensable gas fraction. The noncondensable gas is compressed to atmospheric pressure by a noncondensable gas removal system. Commonly used noncondensable gas removal systems use steam jet gas ejectors with inter and after condensers or mechanical gas compressors with inter and after coolers; hybrid systems using both ejectors and mechanical gas compressors are in use. The inter and after coolers perform the same function as the inter and after condensers; henceforth the designation "condenser" will include "coolers" used with mechanical gas compressors. Noncondensable gas removal systems can include a precondenser ahead of the first stage of compression.
Two types of condensers are used for the main condenser and for condensers in the gas removal system:
(a) direct contact condensers; PA1 (b) surface (shell and tube) condensers.
The present invention is applicable to systems using a surface condenser for the main condenser. Usually the same type of condenser as the main condenser is used in the noncondensable gas removal system. Hence when the present invention is applicable, the condensers in the gas removal system will usually also be surface condensers. Direct contact condensers in the noncondensable gas removal system are also applicable in the present invention; however, surface condensers are preferred.
When employing surface condensers, generally from less than 5% up to about 40% of the hydrogen sulfide present in the geothermal steam is dissolved in the geothermal steam condensate. The remainder of the hydrogen sulfide, from more than 95% down to about 60%, is discharged from the noncondensable gas removal system in the noncondensable gas fraction. Hydrogen sulfide present in the noncondensable gas fraction may then be removed by a primary hydrogen sulfide abatement system which absorbs hydrogen sulfide from the gas stream.
Removal of dissolved hydrogen sulfide from the geothermal steam condensate or from the circulating water is generally accomplished by means of a secondary hydrogen sulfide abatement system, which typically involves the introduction of chemical agents in solution with the dissolved hydrogen sulfide. Condensate produced by the main surface condenser and by surface condenser(s) in the noncondensable gas removal system can be treated either before being added to the circulating water or treatment can occur in the circulating water.
In an alternative combined primary and secondary hydrogen sulfide abatement system, the noncondensable gases are burned to produce sulfur dioxide which is scrubbed from the effluent gas using caustic. In this abatement process, iron chelate is used to convert dissolved hydrogen sulfide to elemental sulfur and water. The elemental sulfur is converted to soluble thiosulfate by reaction with the sulfite ions which are produced by the primary process scrubber.
One commonly used process for removal of hydrogen sulfide from geothermal steam condensate uses hydrogen peroxide to produce elemental sulfur and soluble sulfur compounds. Typically chelated iron is used to catalyze the reaction.
Another process for secondary hydrogen sulfide abatement involves the introduction of ferric chelate in the circulating water loop. Dissolved hydrogen sulfide is oxidized to sulfur by ferric chelate, while the ferric chelate is reduced to ferrous chelate. Ferrous chelate is then converted in the cooling tower, in the presence of air, to ferric chelate, and the ferric chelate is recirculated for continuing secondary hydrogen sulfide abatement. Additional ferric chelate is added as makeup to compensate for chemical lost in the blowdown from the system and to maintain a sufficient concentration (excess stoichiometric amount) of ferric chelate to react with substantially all dissolved hydrogen sulfide in the circulating water. Although the secondary hydrogen sulfide abatement systems which are described immediately above are effective, they require substantial quantities of expensive chemicals such as hydrogen peroxide and/or ferric chelate. An object of the present invention is to reduce the consumption of these chemicals, by making the overall abatement system more efficient.